Repositionable Well Plug

ABSTRACT

Systems and methods are provided for moving a well casing plug to desired locations in a well. The well plug system can be located at a desired position, generate a reversible seal at the location, remove the seal, and relocate. Features of the plug system, such as translocating devices, actuating devices, sensors, and casing penetration tools can allow work to be done at various well hole locations, e.g., without requiring continuous physical connections or communications with the surface. The methods include sealing the well casing plug in a casing, opening ports through the casing, facilitating passage of fluids at hydraulic fracturing pressures to formations outside the casing, reversing the seal, and translocation of the plug system to a new location.

FIELD OF THE INVENTION

Well casing plugs are configured to allow casing sealing and movement within the casing. The well plug system can be untethered from the surface and can include controllers to sense well conditions and initiate actions, such as opening or creation of hydraulic fracturing ports. Methods include steps for the system to seal a well casing, open ports through the well casing, and relocation of the system within a well casing.

BACKGROUND OF THE INVENTION

Systems exist to plug a well casing. This can be, e.g., to prevent escape of pressurized fluids to the surface, as a support for sealing an exhausted well, or to seal a region of a well to be stimulated by hydraulic fracturing.

In one example, Inflatable Flowing Hole Plug, to Christensen (U.S. Pat. No. 4,449,584), a pair of inflatable plugs are lowered on a conduit to a well location needing to be sealed from other flows. Once located at the desired position, the plugs are reversibly inflated to prevent movement of fluids past the plug location. The system must receive power from the surface and must be positioned based on the length of the suspension conduit.

In Naedler, Disintegrating Ball for sealing Frac Plug Set (U.S. 2012/0181032), a ball and seat valve includes a ball that dissolves over time on exposure to hydrocarbons in a well casing. The valve body can be threadably sealed into a well casing and receive proximal pressures intended for hydraulic fracturing. The ball prevents the hydraulic pressures from passing distally and the fluids move instead through casing holes to fracture adjacent formations. As the ball eventually dissolves, fluids (e.g., crude oil from distal locations) can pass freely past the valve. The system requires preinstallation in the casing and is single use.

In Bloom, Gripper Assembly for Downhole Tools (U.S. Pat. No. 8,944,161), an assembly can be inserted down a well and anchored at a location by extending shoulders out from the assembly to contact the interior well casing wall. The grippers are urged out by the action of rollers pushing a cam out against the gripper. Further, Bloom describes a crawling motion in which proximal and distal grippers are alternately bound and releast at the casing wall while the body of the assembly changes in length, providing a crawling motion. The assembly is designed to exert forces to tools down hole and must be tethered to the surface to function.

In view of the above, a need exists for a system that is repositionable and reusable, e.g., so that multiple hydraulic fracturing operations can be performed without preinstallation of equipment in the casing, or having to insert wireline-based tools between hydraulic fracturing well stimulation operations. We see that it would be desirable to have independent equipment that can seal well casings at multiple locations over time. Benefits could also be realized through systems that can work independently while other processes are ongoing in adjacent wells. The present invention provides these and other features that will be apparent upon review of the following.

SUMMARY OF THE INVENTION

The present inventions include systems and methods that provide flexibility and independence for operations of working systems within a wellbore. The systems include controllable sealing and tractor mechanisms that allow selection of sealing locations. Further, the systems can have complementary tools that facilitate down hole operations. For example, the systems can have mechanisms to rigidly retain the plug at a location, in the face of intense pressures experienced in hydraulic fracturing operations. Sub-systems can include reversibly actuated seals, gripper features, tractor features, length extension features, and tools to open or create ports through the casing. The systems can include communication systems, sensor systems, and logic systems that allow independent or semi-independent operations without continuous interaction with the surface.

Exemplary methods that employ features of the well casing plug systems can include actions to carry out repeated fracturing operations at multiple locations. For example, a mobile well plug system can be lowered and released into a well bore. At a desired location, a distal expandable seal can be actuated to seal the plug at the location. To further brace the system against pressures in the casing, grippers can be extended out to contact the well casing. Pyrotechnics carried by the system can be fired to perforate holes through the casing. Frac fluids and proppant can be introduced at high pressures to flow through the holes thus created and out the holes to fracture the local formations. The seal and grippers can be released and a tractor device extended in contact with the inside casing wall to transport the system to a new desired location within the well casing, e.g., to perform additional fracturing processes.

The present invention solves several problems we have identified in the prior art. The present self-contained multi-state well plug embodiments include repositionable elements which relocate, seal, and unseal to serve as a plug for a series of frac (hydraulic fracturing) stages along one wellbore or a set of interconnected wellbores. In one embodiment, the present invention incorporates casing perforation capability. The present invention is useful for stimulation of onshore wells, deepwater wells, and ultra deepwater wells. Alternately, the systems may be used in other applications. The present invention can incorporate electronics, energy storage devices, and actuators in one or more mobile downhole tools, rather than in permanent downhole components, thus reducing costs. Alternately, sensors may be placed on casing segments to acquire well flow and other data over time. In another aspect of the invention, electromagnetically induced signals are transmitted along the well casing to communicate with the repositionable plug and other components while they are downhole.

The present invention has several major advantages over the prior art. The present invention is intended to reduce well completion costs and increase well production. One major advantage of the present invention over the prior art is that the present invention does not leave complex mechanisms downhole during cementing operations, thereby avoiding potential cement residue that may impair future operation.

Since the repositionable plug is repositioned for each frac stage and retrieved from the well after stimulation, it eliminates the costly and time consuming process of milling the frac plugs to remove them after the well stimulation is completed. Thus, well completion costs are reduced and the well is in production mode more rapidly, thereby reducing formation damage.

In addition, the present invention minimizes costly and time consuming trips downhole during the well completion process. A single downhole trip preferably by a wireline-connected deployment tool is needed to place the repositionable plug. A second downhole trip preferably by a wireline-connected retrieval tool is needed to retrieve the repositionable plug. Optionally, sleeves may be placed in the well casing before it is inserted into the wellbore. Each frac stage may be tested in situ and individually optimized to increase the production yield from each stage. The present invention does not require the use of expensive coiled tubing for fracing the well nor for milling out the plugs after well stimulation. The preferably untethered repositionable plug allows for an unlimited number of frac stages per well. The repositionable bore plug is compatible with horizontal, vertical, or inclined wellbores.

Prior art inventions (e.g., Naedler—U.S. 2012/0181032, above) use dissolvable frac plugs which typically dissolve over a time period ranging from two to five days to allow hydrocarbon production from the well. Dissolving plugs can reduce the time to production and reduce cost as compared to the time required post frac to mill out non-dissolvable frac plugs. However, this old art procedure can significantly increase the likelihood of undesirable residual proppant (e.g., sand) packing in the wellbore proximal to the dissolved plugs substantially reducing flow from the well even after the frac plugs dissolve. Advantageously, the present invention allows immediate removal of the plug from the well after fracing, avoiding the residual proppant packing problem.

An aspect of the invention includes systems for repositioning a well plug. For example, a down hole plug system for sequential fracking along a well casing can include a seal and means to reposition the plug in a well casing. The system can include a plug body, an expandable seal mounted on the body and adapted to expand and reversibly seal the body in a well casing, and one or more first casing grips mounted to the body and adapted to extend out from the body and engage the well casing, thereby fixing the plug at a location in the well casing. The seal can be resilient and have a fluid inlet to receive a fluid under pressure, so that a pressurized fluid can expand the seal to contact the well case forming a hydraulic seal. The casing grips can have grip teeth directed away from a body axis. The casing grips can be mounted to the body on a pivot with the grip teeth adapted to grip the well casing when the grips are forced out radially from the body. In one embodiment, the grips are forced out radially by a cam and roller system in the body. Optionally, the well casing, or a coupling between well casing segments, can have an internal ridge so that the grips can extend to contact the ridge, providing structural support and preventing the plug from moving past the ridge.

The well plug can be repositioned, e.g., by alternately gripping and releasing, e.g., with proximal and distal grips, in association with changes in length of the plug body, so that the system crawls along the well, for example, the system can further comprise one or more distal grips distal to the first proximal grips, and one or more extension means (e.g, extension cylinders, rack/pinion, threaded rod, etc.) between the proximal and distal grips, whereby the distance between the proximal grips and distal grips can be increased and/or decreased. Such crawling can be accomplished within the well casting, e.g., by first gripping with a proximal or distal grip, increasing the distance between the proximal and distal grips, releasing the first gripping proximal or distal grip, second gripping with an alternate grip not used in the first gripping, and reducing or increasing the distance between the proximal and distal grips by increasing or decreasing a length of the one or more extension cylinders.

In another embodiment of down hole plug systems for sequential frac processes along a well casing, the plug can be repositioned using one or more drive wheels. For example, the plug system can include a plug body, an expandable seal mounted around the body and adapted to expand and reversibly seal the body in a well casing, one or more drive wheels mounted to the body and extendable out from the body to engage the well casing, and a source of power to turn the one or more drive wheels, thereby moving the plug system along the well casing. The drive wheels can be extendable using a drive piston, e.g., and be powered by a motor in the plug body. The system can include one or more idler wheels mounted to the plug body and acting to space the plug body away from the well casing and to urge the drive wheel against the inside of the well casing for traction. The drive wheel embodiment can also include one or more casing grips mounted to the body and adapted to extend out from the body and engage the well casing, thereby fixing the plug at a location in the well casing, e.g., during casing piercing or fracking operations.

The systems above can include additional features. For example, the systems can include features and ways to direct pressurized fluids into the environment around the well casing, e.g., to facilitate fracturing or well stimulation in oil and gas extraction. For example, the plug body, or associated device, can include a means of perforating the well casing. This casing perforation could involve chiseling, drilling, abrasion, etc., but in a preferred embodiment pyrotechnics are involved. Optionally, the system can be positioned into a well segment having one or more frac ports, e.g., preplaced to provide access to the external well casing. For example, the casing can include a port slide movable to alternately open or close the frac port. Optionally, the plug system is untethered to the surface.

The system can include a controller (e.g., a digital computer) and one or more actuators (e.g., motors) configured to energize movement of features, such as, e.g., a proximal grip, a distal grip, an expandable seal, an extension cylinder, and/or the like. The controller can be preprogrammed or adapted to receive instructions from the surface while the plug system is down hole. The controller can be in communication to receive inputs from one or more sensors (e.g., pressure, temperature, pH, etc.) mounted in the plug body.

The present inventions include methods of repositioning a system within a well casing, and methods of well stimulation such as hydraulic fracturing (fracturing). In one method of fracturing a well at multiple locations, a well casing plug is provided comprising a plug body comprising a proximal end and a distal end, an expandable seal mounted on the body and adapted to expand and reversibly seal the body in a well casing. A propelling device is mounted to the plug body to contact the inside of the well casing and move the plug body along the well casing. The plug body can be sealed (preventing fluids to flow past the position of the plug body in the well casing), e.g., by an expandable seal against the well casing. A port or perforation can be opened through the well casing and the inside of the well casing is pressurized, e.g., so fluids flow through the opening, exposing the outside environment to fracturing pressures. With fracturing complete, the seal can be unsealed from the well casing, freeing the plug body for repositioning. Using a propelling device (e.g., grips or drive wheels) the plug can be moved to a different location within the well casing. By repeating these steps, the plug body can complete fracturing at one location, then move on to another location for additional fracturing.

Repositioning and fracturing with the well plug system can be by any appropriate means, For example, the system can use a propelling means described herein, e.g., such as a drive wheel or a grip/expansion cylinder combination. The system can gain access to the environment outside the well casing, e.g., by opening a port prepositioned in the well casing or by opening a perforation by use of pyrotechnic charges.

A preferred embodiment of the repositionable frac plug uses pyrotechnic charges to perforate the casing in combination with one or more repositionable plugs and a deployment and retrieval tool (referred to herein as the “DR tool”). This embodiment can use casing joints with ridges on the inside diameter to axially register and structurally support the repositionable well plug. The perforating charge embodiment does not require port slides in the well casing. Pyrotechnic charges are preferably attached to the repositionable plug. They may be positioned axially, rotated angularly, and fired sequentially by the repositionable well plug at the proper location for each frac stage. Alternately, pyrotechnic charges may be incorporated in conventional pyrotechnic perforation guns inserted from the wellhead while the repositionable plug remains in the wellbore.

Another embodiment of the system uses movable port slides in the wall of a well casing segment as shown in FIG. 19 and FIG. 20 in combination with one or more repositionable plugs and a DR tool. The movable port slides operate by sliding axially along the casing segment to expose ports in the casing wall.

In a further embodiment of the present invention casing grips are used on the repositionable plug to grip the inside diameter of the casing, locking the plug into position for a frac stage, thereby eliminating the need for the flanged casing joints.

Testing of each stage prior to fracing may be accomplished by observing flow as a function of pressure or temperature for a specific frac stage and by measuring differential pressure, differential temperature, or other parameters. The measurement of these data may allow inference of the well production characteristics at or near that specific location. Using this information, frac parameters, such as flow rate, pressure, proppant type and density, and/or stage duration, may be optimized for localized shale conditions at or near that frac stage. Additionally, thief zones in the shale, which can decrease well production, may be identified and avoided through identification of patterns in the observed well data. Each frac stage may be tested prior to fracing with lower pressure, reduced proppant, and/or lower fluid flow than required to stimulate the stage, to determine if the stage is likely to be highly productive. If data indicates that the stage is expected to have low production, the frac (stimulation) for that stage may be skipped and the movable plug may be repositioned at the location of the next frac stage. Frac stages may be more optimally spaced by locating frac stages closer together in high production zones of the well, and by avoiding well locations which may drain production due to faults or other features in the shale. Additionally, more extensive frac treatments may be provided in highly productive zones of the well.

As with the inventions of the parent application, the present invention enables immediate production from the well, thus increasing the overall hydrocarbon output of the well by reducing formation damage. After fracing, a well placed into immediate production can have substantially increased production for the life of the well if properly choked. Production can increase by as much as 30% or more while potentially reducing completion costs from shale oil and gas wells and other types of wells. Thus, the present invention may increase production of hydrocarbons per well due to a) the ability to get the well in production sooner due to not needing to mill out the bridge plugs, b) the optimization of the frac parameters for each well stage, and c) the ability to skip marginally productive or thief zones.

In a preferred embodiment of the present invention, casing perforation charges are incorporated into the repositionable plug. This embodiment has the further advantage of accommodating variable length frac stages even if the well casing was not fully inserted into the drilled wellbore. This embodiment further allows different types of pyrotechnic charges to be optimally used for different shale condition at different frac stages along the well length. For example, pyrotechnic charges may be optimized for different shale permeabilities. The pyrotechnic charges on the repositionable plug may be rotated into optimal orientation with respect to the plane of the shale layer. The perforation charges may advantageously be optimized in quantity, type, and spacing for the geology and expected production at each frac stage.

The repositionable plug can be configured to evenly distribute the weight of the plug over the length of the plug. The repositionable plug is preferably corrosion resistant to enable it to be employed even when hydrochloric acid is pumped downhole to treat the formation prior to fracing or to treat carbonate reservoirs. The repositionable plug is easily serviced after removal from the well. In the rare event of a failure, the repositionable plug is preferably designed to fail in an easily retrievable state. Optional sliding sleeves in the well casing are preferably corrosion resistant and therefore may be left downhole for years after the casing is completed but before the well is fraced.

DEFINITIONS

Before describing the present invention in detail, it is to be understood that this invention is not limited to particular devices, which can, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used in this specification and the appended claims, the singular forms “a”, “an” and “the” include plural referents unless the content clearly dictates otherwise. Thus, for example, reference to “a surface” includes a combination of two or more surfaces; reference to “proppant” includes mixtures of proppant, and the like.

Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which the invention pertains. Although any methods and materials similar or equivalent to those described herein can be practiced without undue experimentation based on the present disclosure, preferred materials and methods are described herein. In describing and claiming the present invention, the following terminology will be used in accordance with the definitions set out below.

As used herein “fracing” or hydraulic fracturing is a well-stimulation technique in which rock in the well is fractured by a pressurized liquid.

As used herein a well casing is as known in the art of hydrocarbon exploration or water well drilling. For example, an oil well casing is typically the pipe that is assembled and inserted into a recently drilled section of a borehole. Although other pipes and strings may be inserted into the well hole, the casing is the inner most pipe down hole.

As used herein, a “plug” is a device that functions to seal a pipe, such as a well casing, against flow of fluids therethrough. An expandable plug is configured to expand radially to come in contact and seal against the inside wall of a pipe, such as a well casing. A reversibly sealable plug may be adapted to, (e.g., alternately be expanded to) contact and seal a pipe, then contracted to release the seal.

As used herein, directions are as commonly used. For example. up is opposite the force of gravity on earth. In the context of a well bore, axially is along the center axis of the bore, radially is out away from the axis, e.g., perpendicular to the axis. Proximal is toward the end of the bore where the drill or casing was inserted (typically closer to the earth's surface) and distally is in the direction in which drilling progressed (e.g., away from the earth's surface). Down hole refers to the well below grade level.

As used herein, a controller is a, digital processor, as known in the art.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a perspective view of the repositionable plug.

FIG. 2 is a perspective view of the repositionable plug without housing.

FIG. 3 is a cross-sectional perspective view of the distal end of the repositionable pug.

FIG. 4 is a Cross-Sectional Perspective View of the Distal End of the Repositionable Plug with Ram Extended.

FIG. 5 is a Cross-Sectional Perspective View of the Distal Cam Piston Subassembly with casing grips retracted.

FIG. 6 is a Cross-Sectional Perspective View of the Distal Cam Piston Subassembly with casing grips extended.

FIG. 7 is a Cross-Sectional Perspective View of the Proximal Cam Piston Subassembly.

FIG. 8 is a Cross-Sectional Perspective View of the Proximal Cam Piston Subassembly with casing grips extended.

FIG. 9 is a Cross-Sectional Perspective View of the Proximal Cam Piston Subassembly with casing grips and seal extended.

FIG. 10 is a Perspective View of the Preferred Proximal and Distal Casing Grip.

FIG. 11 is a Perspective View of the Alternate Proximal Casing Grip.

FIG. 12 is a Cross-Sectional Perspective View of a Repositionable Plug Center Section.

FIG. 13 is a Cross-Sectional Perspective View of the Proximal Center of Repositionable Plug.

FIG. 14 is a Diagram of the Hydraulic Circuit.

FIG. 15 is a Cross-Sectional Perspective View of the Extraction Tool Engaged with the Repositionable Plug.

FIG. 16 is a Perspective View of the Proximal End of the Repositionable Plug with Perforators.

FIG. 17 is a Cross-Sectional Perspective View of the Repositionable Plug Tractor Drive Subassembly.

FIG. 18 is a Cross-Sectional Perspective View of the Repositionable Plug Drive Piston.

FIG. 19 is a Cross-Sectional Perspective View of a Casing Segment with the Port Slide in the Closed Position without the Plug.

FIG. 20 is a Cross-Sectional Perspective View of a Casing Segment with the Port Slide in the Open Position without the Plug.

FIG. 21 is a Diagram of the Control System.

FIG. 22 is a Cross-Sectional Perspective View of the Extraction Tool.

FIG. 23 is a Cross-Sectional Perspective View of the Casing Coupling with Casing Joints.

DETAILED DESCRIPTION

One embodiment of the present invention is repositionable plug 10 shown in FIG. 1. The preferably cylindrical body 11 of repositionable plug 10 has a preferably tapered distal end 12 with a plurality of distal casing grips 13. The proximal end of plug 10 preferably has a plurality of proximal casing grips 14 and a sensor cavity 16 preferably proximal to elastomeric seal 9. The body of plug 10 is preferably smaller than the inside diameter of the well casing and short enough to pass through curved sections of well casing and imperfections such as doglegs and partially collapsed sections without interference. Plug 10 may optionally contain one or more movable joints to make it flexible enough to pass through, if required. Repositionable plug 10 shell is preferably fabricated of steel alloy, titanium alloy, composite, ceramic, and/or other suitable material.

Each repositionable plug 10 accommodates a predetermined range of casing inside diameters. For example, an 8.57 cm (3.375 in) outside diameter repositionable plug is suitable for a 14 cm (5.5 in) outside diameter 20 lb/ft well casing having a 12.11 cm (4.77 in) inside diameter or a 17 lb/ft well casing, or a 23 lb/ft well casing. Repositionable plug 10 preferably has a maximum retracted length less than 5 m (16 feet) and preferably has a diameter of 8.57 cm (3.375 in) or less to enable it to pass through problem areas in the well casing during insertion and extraction from the well. The small diameter of plug 10 allows ease of movement through a 90 degree radiused bend in the well casing connecting the vertical portion of a shale well to the horizontal portion of the well. Optionally, incorporating articulated joints along plug 10 length may increase plug 10 length. Smaller diameter versions of plug 10 may be designed for use in smaller diameter casings used for ultra deepwater wells. Alternately, another suitable length and diameter may be chosen.

An impact-absorbing bumper is preferably located on the distal end of plug 10 to protect against collision with the bottom hole assembly or other object. An impact-absorbing bumper may additionally be placed on the proximal end of plug 10 to absorb impact from collisions with the extraction tool or other downhole tools.

Sensor cavity 16 preferably includes one or more pressure sensors configured to measure absolute pressure in the wellbore and to receive pressure pulse signals through the wellbore. Sensor cavity 16 is preferably located proximal to elastomeric seal 9 to prevent pressure signal attenuation when seal 9 when is expanded. Additional pressure sensors may be configured to obtain static and dynamic pressure measurements. Sensor cavity 16 can contain one or more thermal sensors such as thermocouples or thermistors. Additional thermal sensors may be located at the distal end of plug 10 to obtain differential temperature measurements.

Sensor cavity 16 preferably houses radially sensing hall effect sensors or other sensors configured to detect the axial position of casing couplings with respect to ridges 15 or other well casing features or to detect couplings between sections of well casing. Sections of well casing are commonly referred to as “joints.” The Hall effect sensors may also be used to detect burrs on the casing inside diameter resulting from pyrotechnic perforations. Alternately, ultrasonic or other sensors can be used. Optionally, sensor cavity 16 or other locations on plug 10 may contain a coil or other sensor for receiving electromagnetic induction signals transmitted along the well casing from the wellhead or from the deployment and retrieval tool or from other components or downhole tools. Optionally, sensor cavity 16 or other locations on plug 10 may contain an induction coil transmitter for transmitting status signals and other data from plug 10 to the wellhead or to other downhole tools. Sensor cavity 16 is preferably sealed with O-rings or other sealing elements to prevent intrusion of fluids from the well bore. Sensor housing 16 may be fabricated from non-magnetic material to enhance the sensitivity of the Hall sensors. In addition, magnetic susceptors may be used to increase Hall effect sensor sensitivity. Alternately, other materials or sensor types may be used. Proximal tip 81 of plug 10 may further include a magnet or other means to provide a proximity signal to DR tool. Proximal tip 81 may further contain an energy absorbing bumper element.

In a preferred embodiment of the invention, perforation guns may be attached to plug 10 to eliminate the need for additional downhole trips to perforate the casing between frac stages. Multiple sets of perforation charges to enable multiple stages to be perforated may be attached to plug 10. FIG. 16 shows multiple perforation guns 163 attached to the proximal end of plug 10 distal to helix 80 and proximal to sensor cavity 16, seal 9, and other parts of plug 10. Perforation charges 161 are shown helically arranged for each stage on perforation guns in FIG. 16. Alternately, perforation guns 163 may located on the distal end of plug 10 or at any other suitable location. U-joint 162 shown in FIG. 16 allows the entire plug 10 system to articulate to pass through radii or doglegs or other imperfections or tight locations in the casing. Multiple U-joints may be used if required.

FIG. 2 shows the embodiment of repositionable plug 10 from FIG. 1 with the outer shell removed. Outer shell 11 (body) is designed to provide structural integrity during operation and to prevent fluid intrusion from high downhole pressures. Repositionable plug 10 preferably has a distal valve body 20 that preferably contains at least two hydraulic solenoid valves and a proximal valve body 21, which preferably has at least one hydraulic solenoid valve. The hydraulic solenoid valves are preferably low resistance three-way valves. A spring return design of each hydraulic cylinder allows simple three-way valves to be used. Alternately, servo valves may be used. Alternately, another type of valve may be used. Hydraulic reservoir 22 is suitably located within plug 10. Hydraulic reservoir 22 may be located at any suitable location, including at least partially in the interstitial spaces of the batteries 17. High temperature hydraulic fluid such as a phosphate ester based hydraulic fluid, for example Exxon HyJet V, is preferably used as the working fluid in the hydraulic system. Alternately, any other suitable hydraulic fluid may be used. Alternately, mechanical actuators or others means are used instead of the hydraulic system.

Motor 18 is preferably a brushless DC motor equipped with multiple hall effect sensors for use in controlling its angular position, rotational speed, and current through monitoring its rotational position and velocity. Motor 18 preferably has temperature sensors to enable monitoring of motor temperature to prevent overheating. Alternately, another type of motor is used. Alternately, another means is used to drive hydraulic pump 19. Motor 18 is preferably immersed in a heat dispersing fluid or gas to assist in cooling to enable greater output power. Possible cooling fluids include fluorocarbon fluids such as perflourohexane, perflouro methyl cyclohexane, perflouro 1,3 methylcyclohexane, perflouro decalin, and perflouro methyl decalin. Alternately, oil, hydraulic fluid, or other fluid may be used. Sealed conduits between bulkheads may pass cables and hydraulic lines through the motor section of the casing while isolating the motor cooling fluid.

An array of batteries 17 preferably powers motor 18 through a suitable multi-phase H-bridge amplifier or other smart servo drive method commonly known to those skilled in the art. The servo drive is preferably controlled via a pulse width modulated signal supplied by the microcontroller described below. Alternately, current to motor 18 may be switched directly from batteries 17 or from another source. Alternately, a mud motor or other power source may be used. Motor 18 preferably drives hydraulic pump 19 though a planetary gearbox or other type of gearbox to provide optimal torque and speed. A multiple speed gearbox may be used if desired.

Hydraulic pump 19 is suitably plumbed to provide proper pressure and flow to both the proximal and distal valve bodies. Hydraulic pump 19 is sized to provide fluid power to four spring return pistons controlled by the proximal valve body 21 and distal valve body 20 including extension cylinder 32 as shown in FIG. 4, distal cam piston 45 as shown in FIG. 5 and FIG. 6, proximal cam piston 77 and elastomeric seal piston 76 as shown in FIG. 7. All piston springs are preferably preloaded, with tension urging the associated piston axially. Pump 19 is also capable of powering other fluid powered elements as needed. Alternately, double acting cylinders may be used. Alternately, another type of drive system such as a motor driven mechanical system may be used.

The volume of hydraulic fluid pumped by pump 19 is monitored by tracking pump rotations computed from motor 18 hall sensor signals and by monitoring fluid temperature to infer displacement of pistons. Alternately, piston displacement may be measured directly through encoders or other means. Pressures from proximal and distal pressure sensors can also determine pressures in the piston cylinders, from which piston displacements and grip and seal forces may be computed since all pistons have pre-loaded return springs with known spring constants. Alternately, another method or direct measurement by displacement transducers may be used.

Batteries 17 preferably have sufficient capacity to be used to frac one or more wells. Alternately, battery capacity may allow for less than one well to be fraced, requiring multiple repositionable plugs 10 to be used sequentially for each well or requiring batteries 17 to be replaced between frac stages. Careful programming of repositionable plug 10 can optimize battery life, for example by only partially closing the distal grips 13 during repositioning of the repositionable plug 10 to reduce power requirements.

FIG. 3 shows a cross-sectional view of the distal end of repositionable plug 10 with extension cylinder 32 retracted and distal cam piston 45 and distal grips 13 retracted. Flexible hydraulic hose 30 directs fluid through the central bore in extension cylinder 32 to transfer fluid to distal cam cylinder 48, urging distal cam piston 45 to extend distal casing grips 13. Since flexible hose 30 has minimal volume change despite the large displacement of extension cylinder 32, extension cylinder 32 motion is effectively decoupled from distal grip 13 motion, enabling grips 13 to maintain proper clamping force against the casing wall even as extension cylinder 32 moves. This design eliminates the need to expend energy to actuate the distal hydraulic solenoid valve to maintain proper pressure in distal cam cylinder 48 during extension cylinder 32 motion. Alternately, another type of fluid transfer conduit is used. Alternately, another means of fluid transfer to the distal end of plug 10 may be used. Optionally, a conduit for distal sensor cables may traverse the center of extension cylinder 32.

As extension cylinder 32 extends, increased hydraulic pressure is required due to the increasing force needed to compress the return spring 49 as shown in FIG. 2 and FIG. 3. Added to this force is the force needed to push plug 10 through the proppant pack remaining in the well bore after the previous frac stage, since the wellbore may be packed with proppant and gel for up to several meters proximal to plug 10 after each frac stage is completed.

Hydraulic fluid accumulates in reservoir 22, which is comprised in part by outer shell 11. Alternately, fluid reservoir 22 may be completely separate from the outer shell. Compression spring 25 exerts force on piston 23 as shown in FIG. 3 to maintain sufficient pressure on the hydraulic fluid in reservoir 22 to keep reservoir 22 free of air or other gases or fluids independent of the orientation of plug 10. Alternately, a bladder may be used to maintain pressure in the reservoir. Coaxial tubes 24 pass through fluid reservoir 22 to direct hydraulic fluid to and from distal cam cylinder 48 and extension cylinder 32. Alternately, tubes may be used that route around a discrete reservoir.

FIG. 4 shows extension cylinder 32 fully extended with distal cam piston 45 retracted. Hydraulic fluid is pumped into extension cylinder cavity 34 to urge the extension cylinder to extend. Tube 33 inside cylinder 32 is needed to contain the hydraulic fluid and to prevent fluid from escaping into cylinder 32 inner cavity, which houses flexible hydraulic hose 30.

Distal cam piston 45 is displaced by hydraulic pressure in cylinder cavity 48 as shown in FIG. 6 to extend distal grip 13. Distal cam piston 45 preferably has a pocket for each distal casing grip 13 enabling distal casing grips 13 to retract for wellbore insertion, wellbore extraction, and movement between frac stage positions. Repositionable plug 10 preferably has at least three proximal grips 14 and at least three distal grips 13. Preferably, each set of proximal grips 14 or distal grips 13 are radially arranged and each set is preferably driven with a single cam piston. Alternately, plug 10 has at least one proximal grip 14 and at least one distal grip 13. Alternately, more than one cam piston may be used per grip set. A roller cam follower 47 is preferably used on both the proximal and distal cam pistons 77 and 45 to reduce friction and reduce cam wear due to the presence of abrasive proppant downhole.

FIG. 5 shows distal cam piston 45 with distal grip 13 in the retracted position. As hydraulic pressure in piston cavity 48 creates force on distal cam piston 45 greater than return spring 44 preload force, spring 44 compresses, causing distal cam piston 45 to move distally and forcing roller cam follower 47 to climb cam 42. The steeply inclined ramp portion 42 of cam piston 45 reduces the axial travel required for distal cam piston 45 to deploy and retract distal grip 13 from the storage pocket in the cam piston. Preferably, the angle of the steep ramp portion is 25 to 35 degrees with respect to the piston axis. Alternately, any other suitable angle may be used. The shallow ramp angle on the further deployment portion 43 of distal cam piston 45 enables distal casing grips 13 to engage with a predetermined range of casing diameters and to accommodate the presence of foreign material in the wellbore. Preferably, the angle of the shallow ramp portion is 1.5 to 3.5 degrees with respect to the piston axis. Alternately, any other suitable angle may be used. When extended through sufficient hydraulic pressure exerted in piston cavity 48, distal casing grips 13 grip the inside diameter (ID) of the well casing. The thicker cross-section of the cam piston which cam followers 47 roll upon when grips 13 are on shallow ramp portion 43 of the cam while contacting the well casing ID is sized to withstand the higher forces exerted from cam roller 47 onto the cam while casing grips 13 are exerting force on the casing wall. Alternately, other cam angles or profiles may be used. In the preferred embodiment, distal casing grips 13 are cantilevered from roller cam follower 47 as shown in FIG. 5 and FIG. 6 to maximize radial travel of grips 13 from the limited radial motion possible with distal cam piston 45.

Leaf spring 40 as shown in FIG. 5 exerts force radially inward to maintain roller cam follower 47 contact with its respective cam path on cam piston 45. Leaf spring 40 retracts grip 13 into the pocket in cam piston 45 as return spring 44 urges piston 45 to return to its fully retracted position as hydraulic pressure in cylinder 48 is relieved by the three-way valve. Proximal and distal seal protectors 73 and 74 on the outer circumference of plug 10 housing as shown in FIG. 7 prevent damage to seal 9 from abrasion or impact with casing during insertion extraction or movement between stages of the well. Similarly, distal and proximal grip protectors 3 and 4 prevent damage to distal and proximal casing grips 13 and 14 from abrasion and impact with the well casing.

FIG. 6 shows distal cam piston 45 displacing distal casing grip 13 to a typical position for contacting the inner casing wall. The annular well casing and leaf spring 40 are not shown in FIG. 6 for clarity. Preferably, distal grips 13 apply sufficient force to the well casing ID to prevent slippage as plug 10 moves along the well bore. Optionally, distal grips 13 may assist proximal grips 14 in resisting the axial force created by high proximal well pressure. During the frac, well pressures may range from 35,000 kPa to 170,000 kPa (5000 psi to 25,000 psi). Alternately, lower or higher pressures may be used.

As Grip 13 teeth hold axial location by pressing against the casing ID, plug 10 body moves proximally along the well as extension cylinder 32 extends. Extension cylinder 32 preferably generates sufficient force to push plug 10 through residual proppant and gelling agent in the well bore which is usually found proximal to the plug after the frac stage is completed. The residual proppant and gelling agent in the well bore proximal to the plug after the frac stage is completed is commonly referred to as the “proppant pack.” Consolidated wet 20/40 mesh Ottawa white sand proppant commonly used in fracs has static shear strength of approximately 350 kPa (50 psi), which must be exceeded to initiate motion through the proppant pack. Consolidated wet 20/40 mesh Ottawa white sand proppant has a kinetic shear stress of 180 kPa (25 psi), which must be exceeded to maintain motion through the proppant pack. Both the proximal grips 14 and distal grips 13 preferably have teeth fabricated from titanium alloy, zirconium alloy, high strength steel alloy, maraging steel, ceramic, metal-matrix composite, other high strength alloy, or any other suitable material. Optionally, the teeth on the grips may be removably mounted to the grips. The grip body may be fabricated of a different material than the grip teeth.

The spring return design of proximal cam piston 77 and distal cam piston 45 enable these pistons to partially retract proximal grips 14 and distal grips 13 between frac stages without requiring servo valves or double acting cam cylinders, thus simplifying the system. In case of hydraulic system failure, the piston return springs exert force to retract extension cylinder 32, proximal grips 14 and distal grips 13 and seal expansion piston 76 to allow plug 10 to be retrieved from the wellbore by the retrieval tool.

FIG. 7 and FIG. 8 show an embodiment of proximal grips 14 and their actuation subsystem similar to the embodiment of distal grips 13 and their respective actuation subsystem described above. Proximal cam piston 77 is displaced by hydraulic pressure in cylinder cavity 86, as shown in FIG. 8 to extend proximal grips 14. Proximal cam piston 77 preferably has a cavity for each proximal casing grip 14 to allow proximal casing grips 14 to retract for well insertion, well extraction, and movement between frac stage positions in the well. FIG. 7 shows proximal cam piston 77 with proximal grip 14 in the retracted position.

As hydraulic pressure acting upon proximal cam piston 77 creates sufficient force on proximal cam piston 77 to exceed spring 72 preload force, spring 72 compresses, urging proximal cam piston 77 to move distally and forcing the roller cam follower to roll up the incline on proximal cam piston 77. As proximal grips 14 are thus urged radially outward, proximal casing grips 14 exert outward force on the ID of the well casing, thus locking casing grips 14 to the well casing. Meanwhile, leaf spring 71 exerts a lesser radial force inward to maintain the roller cam follower contact with the cam path on its respective cam piston. FIG. 8 shows proximal cam piston 77 displacing proximal casing grip 14 to a typical position for contacting the inner casing wall. The annular well casing and its corresponding leaf spring are not shown in FIG. 8 for clarity.

The leaf spring retracts grip 14 back into cam cavity as return spring 72 urges piston 77 to move back to its fully retracted position as hydraulic pressure in cylinder 86 is relieved by the three-way valve. Leaf spring 71 is captured in groove 105 in grip 14 as shown in FIG. 10 and centered by a slot in the leaf spring to maintain lateral registration of grip 14 in piston cam slot by notch 106. Roller the cam follower rotates on a pin in bore 104 in casing grip 14. The cam follower returns to the pocket in cam piston 77 when cam piston 77 is fully retracted.

As plug 10 moves along the wellbore between frac stages, proximal grips 14 preferably grip the well casing ID with sufficient force to hold plug 10 stationary while extension cylinder 32 retracts. When fluid and proppant are injected into the wellbore during the frac stage, high proximal well pressures cause compressive force on the proximal end of plug 10. This force is transferred through proximal grips 14 to the well casing. Differential well pressures during the frac stage may reach 35,000 kPa to 100,000 kPa (5000 to 15,000 psi) or more. Proximal grips 14 transfer axial force on plug 10 to ridges 15 in the casing couplings during the frac stage to resist these forces, thus causing high compressive forces in grips 14. Alternately, proximal grips 14 may transfer the forces to the casing directly through teeth or other features on grips 14. Alternately, proximal casing grips 14 may be expanded and retracted by a rotating an inner threaded member or by a rotating an inner piston or by other means. Alternately, another means of anchoring the plug 10 against the casing may be employed.

Axial port 7 preferably passes through proximal cam piston 77 offset from piston 77 centerline to transfer fluid to proximal cam cylinder cavity and sealing piston cylinder cavity 86. Electrical and signal cables from Hall effect sensors, temperature sensors, pressure sensors, and other sensors in sensor cavity 16 and from other locations proximal to pistons 76 and 77 may pass through center conduit 70 which passes through both proximal pistons to the sensor electronics PC board. Both proximal cam piston 77 and sealing piston 76 seal on center conduit 70.

The distal and proximal cam cylinders 48 and 86 and distal and proximal cam pistons 45 and 77 are preferably fabricated from high tensile strength steel, titanium alloy, metal matrix composite, ceramic, or any other suitable material. They may be shot peened, nitride treated, heat treated, or otherwise processed to increase hardness and wear resistance. They may be plated or otherwise treated for corrosion resistance and wear resistance.

Elastomeric seal 9 is expanded as shown in FIG. 9 after plug 10 has reached its proper axial location for a frac stage. As shown in FIG. 7 and FIG. 8, proximal cam piston 77 and sealing piston 76 share common cylinder cavity 86 and are activated sequentially to expand grips 14 and elastomeric seal 9. Alternately, another design may be used (e.g, with separate cylinders for each piston). Pressure to operate seal piston 76 is supplied through port 7 as shown in FIG. 8, which passes through adjacent proximal cam piston 77. The hydraulic pressure required for seal piston 76 to overcome return spring 78 preload force and initiate motion by compressing return spring 78 is preferably higher than the hydraulic pressure required for adjacent proximal cam piston 77 to reach its end of travel. Seal piston 76 urges the tapered proximal end of annular wedge 75 shown in FIG. 9 to slide axially into the distal inner diameter of elastomeric seal 9, thereby radially expanding seal 9 to form a pressure resistant seal against the well casing ID to prevent proximal pressure loss from the frac stage. Elastomeric seal 9 is preferably fabricated from a high temperature chemical resistant polymer or copolymer such as DuPont Viton, FKM flourocarbon, FPM, FFKM perflouroelastomer, flouropolymer, silicone, blends of these or other polymers, or any other suitable material. Alternately, an expanding sleeve (e.g., mechanically) may be used to increase the elastomeric seal ID. Alternately, a leadscrew or other mechanism may be used to slide one or more tapered elements to expand seal element 9. Alternately, radially expanding overlapping or helical overlapping cam segments or helical cam segments may be used. Alternately, a non-elastomeric material may be used for seal 9. Alternately, the seal may have another design. Alternately, another type of seal (preferably releasable or reusable) may be used.

Protective rings 73 and 74 on either side of elastomeric seal 9 are slightly larger in diameter than the retracted outer diameter of seal 9 to protect seal 9 from abrasion or other damage as plug 10 is inserted or retracted from the well or moved along the wellbore. Protective rings 73 and 74 may additionally protect plug 10 as it passes burrs and other imperfections on the casing ID resulting from pyrotechnic perforations and from other causes.

An accumulator may optionally be built into proximal piston 77 to cause elastomeric seal 9 to maintain constant force against the casing ID even though elastomeric seal 9 may experience viscoeleastic creep, or proximal three-way valve 128 may bleed down under pressure. Optionally, additional fluid may need to be pumped into seal piston cavity 86 to maintain sealing pressure during extended frac stages.

Preferred casing grip 13 is shown in FIG. 10. Casing grip 13 may lock onto the well casing at any suitable location along the casing. Casing grip 13 design is preferred for use on both distal grips 13 and proximal grips 14 on plug 10. Preferably, casing grip hinge bore 103 is located proximal to grip teeth 112 for both distal grips 13 and proximal grips 14 on plug 10. The distal portion of casing grip 13 is displaced radially outward to grip the ID of the well casing. Casing grip teeth 112 are intended to secure casing grip 13 by impressing teeth 112 into the casing wall ID by radially outward forces acting on cam roller 47 by cam piston shallow ramp section 43. Teeth 112 increase their well casing gripping force as frac pressures increase because the grip geometry causes grip teeth 112 to have the beneficial effect of transferring increasing force to the casing wall as proximal well pressure on plug 10 proximal end increases during the frac stage. Teeth 112 may be configured to have a cylindrical perimeter or a barrel-shaped perimeter in order to maximize grip contact area for variable well casing diameters. Alternately, another suitable tooth perimeter shape may be used.

Casing grip 13 rotates on hinge pin 104 which preferably resides in hinge bore 103 with respect to plug 10 body. Casing grip 13 is preferably designed to transmit force to plug 10 body instead of requiring hinge bore 103 to bear all the proximal force resulting from the high frac pressure. Hinge bore 103 may be a slotted bore or an enlarged diameter bore with sufficient clearance to enable grip end surface 108 to transmit proximal force to plug 10 casing instead of requiring hinge bore 103 or its corresponding hinge pin to carry the full load.

FIG. 11 shows an alternate embodiment of proximal casing grip 14. Cylindrical surface 100 of grip 14 preferably bears upon the reduced inside diameter of flange 15 (see, e.g., FIG. 23) in a casing coupling. Conical surface 101 of grip 14 bears upon the proximal flange chamfer on casing coupling 2 flange 15.

Casing couplings 2 featuring integral flanges 15 as shown in FIG. 23 are optionally inserted with the well casing string unless expandable flanges or flange segments are later inserted into the casing. Alternately, discrete flange segments may be placed between the ends of the casing joints using conventional couplings. Alternately, the well casing itself can be formed to have the flanges.

Typical frac stages are spaced at 15 m (50 foot) intervals along the well. With an extension cylinder 32 stroke of 46 cm (18 inches), 33 cycles are needed to move repositionable plug 10 15 m (50 feet) proximally for each successive frac stage. Alternately, a different spacing interval may be used. Alternately, the spacing interval may vary between stages. Optionally, repositionable plug 10 may receive inductive signals or pressure signals or other signals transmitted from the wellhead or any other suitable location to command plug 10 to move a specified distance along the wellbore, perforate the well casing, move into position, and seal the well bore for the next frac stage. Optionally, plug 10 may compute the optimal frac stage spacing based on measured parameters and move the appropriate distance in accordance with these calculations, perforate the casing, move distally into position, lock onto the casing, and expand seal 9 in preparation for fracing that well stage. Optionally, plug 10 may transmit a signal through induction coupling to the well casing or other means such as by pressure wave generated by a pyrotechnic device to communicate its readiness for the next frac stage.

FIG. 12 shows an enlarged view of the center section of repositionable plug 10 with the outer casing removed. Three-way valves 126 and 127 are mounted on distal valve body 20. Distal valve body 20 transfers fluid through the coaxial tubes 29, which pass through hydraulic reservoir 22. Coaxial tubes 29 may be used instead of two separate tubes to minimize friction losses and leaks at reservoir piston 23. Alternately, another tubing design may be used. Preferably hydraulic reservoir 22 capacity is equal to at least the sum of the piston displacement volumes to enable fully independent movement of all of the independent pistons on plug 10. Pressure sensors are preferably placed on both high and low pressure ports on both proximal valve body 21 and distal valve body 20.

High flow rate three-way solenoid valves 126, 127, and 128 are preferably used to obtain rapid depressurization of cylinders 34, 48, and 86 for faster movement of plug 10 up the well. Hydraulic supply and return lines 121 and 122 direct hydraulic fluid to and from three-way valves 126 and 128 on proximal valve body 21 as shown in FIG. 12. Proximal valve body 21 is preferably bolted on to a proximal cylinder body. Proximal valve body 21 (FIG. 13) preferably has a three-way solenoid valve 128 with pressure sensors. Hydraulic pressure is supplied by pump 19, which also supplies distal valve body 20. Flexible stainless steel tubing sections 134 and 135 are preferably placed on the hydraulic lines 121 and 122 to and from proximal valve body 21 to prevent the need to open the hydraulic system when plug shell 11 is opened for inspection and battery replacement. Alternately, another type of fluid connection may be used.

Cable slot 131 provides a continuation of conduit 70 pathway from the proximal sensor cavity to the distal electronics board, enabling the cabling for temperature sensors, pressure sensors, Hall effect sensors, and other sensors to pass through the proximal pistons and cylinders from sensor cavity 16 to circuit boards 132 and 133. Sensor PC board 132 and processor PC board 133 are preferably remote from or shielded from motor to minimize electrical interference and signal degradation.

Downhole temperatures can reach 176 C (330 F) for onshore fraced wells and 204 C (400 F) for ultra deepwater wells. Therefore, batteries 17 are preferably lithium thionyl chloride batteries due to their high temperature capability and high energy capacity. Alternately, sodium sulfur, other lithium chemistries, or any other suitable type of battery may be used. Alternately, higher or lower temperatures may be reached. The battery cells are preferably stacked in series and parallel as needed to provide the necessary current and voltage for the electronics operation and for motor and valve operation. Cells may be matched in series or parallel arrangement to optimize power transfer and battery life.

Batteries 17 may be isolated within pressure resisting bulkheads. Hermetically sealed electrical feedthroughs may optionally be used to prevent battery pressures or fluids from affecting other components of the system. The battery compartment may optionally filled with an inert gas or fluid and designed to protect against fire, explosion, or leakage of battery fluids and gasses and to dissipate heat. A vent port may optionally vent gasses above a certain pressure to prevent explosion if needed.

Optionally, one or more capacitors may be placed in circuit with batteries 17 to supply high current pulses when needed. An ultra capacitor or a motor/generator-driven flywheel or a set of motor-driven counter-rotating flywheels may be optionally used to store and retrieve energy for power bursts, if desired. Alternately, instead of batteries, mechanical elements such as springs may be used for energy storage. Alternately, a compressed gas may be used for energy storage. Alternately, downhole mud motors may be used. Optionally, hydraulic lines pass through the battery cavity from pump 19 to proximal valve body 21 to direct hydraulic fluid to and from drive piston cylinder 243, idler piston cylinder 244, and accumulator 270 (see, e.g., FIG. 17).

FIG. 14 shows a diagram of one embodiment of the hydraulic system for plug 10 described above. In FIG. 14, motor 18 drives pump 19 that draws hydraulic fluid from reservoir 22. Optionally, an anti-leak back valve or check valve on pump 19 prevents fluid under pressure from flow back into pump 19. Fluid is then directed through three-way valves 126, 127, and 128 to extension cylinder 32, distal cam cylinder (cavity) 48, proximal cam cylinder 86, and seal cylinder 86 (in shared cylinder embodiment). Maximum hydraulic pressure in the system is preferably below 21,000 kPa (3000 psi). Alternately, another pressure may be used.

Control System

FIG. 21 shows the block diagram of one embodiment of plug 10 control system. In FIG. 21, microcontroller or digital signal processor 150 is preferably operable at high downhole temperatures of up to 176 C or 204 C or higher, such as the Texas Instruments TMS320 series, is used as the main controller. A high temperature chipset preferably capable of operating at high ambient temperatures to support the microcontroller is preferably collocated on a high temperature printed circuit board, signal conditioning circuit board 132, and motor and valve control circuit boards. The high temperature printed circuit boards may be fabricated from polyetheretherketone (PEEK) composite, polyetherimide (PEI) composite, epoxy/glass fiber composite, or other suitable material. The high temperature printed circuit board preferably uses high temperature circuit components and high temperature solder. The high temperature circuit boards may optionally be immersed in flourocarbon fluid or other suitable thermally conductive substance to maximize heat dissipation.

Microcontroller 156 preferably incorporates firmware or software to interpret the sensor signals and issue commands to hydraulic pump drive motor 19 and hydraulic solenoid valves 126, 127, and 128 via pulse width modulated outputs. Pulse width modulated output signals from the microcontroller are preferably amplified through high temperature MOSFETs or by other amplification techniques well known to those skilled in the art. Output signals from sensors such as Hall effect sensors 158 to detect ridges 15 on the casing and Hall effect sensors 158 or other sensors to detect DR tool auger 151 axial distance are preferably electrically filtered and provided as inputs to the analog to digital converter on microcontroller 156. Other sensors, such as hydraulic pressure sensors, downhole temperature sensors, motor temperature sensors, and electronics temperature sensors are preferably similarly conditioned and connected.

One or more strain gages 157 to sense downhole pressure pulses as signals for the beginning or end of frac stages are preferably configured as Wheatstone bridges and connected as inputs to the analog to digital converter on microcontroller 156 after optional amplification. Hall effect sensors 158 or other sensors sense motor position and velocity information and are also preferably connected as high priority inputs to the analog to digital converter of microcontroller 156. Additional sensors for motor current, valve current, and hydraulic pressures may be optionally used. The presence of an insertion or extraction tool may be detected with a with Hall effect sensor on repositionable plug tip 81.

An alternate embodiment of the plug 10 positioning system is shown in FIG. 17. This alternate design employs a tractor drive through drive wheels 241 instead of proximal and distal grips 14 and 13 and extension cylinder 32 as described above. The positioning system enables plug 10 to advance proximally along the well casing from the current frac stage to the adjacent proximal frac stage. Alternately, repositionable plug 10 can travel in the distal direction down the well casing. The drive system is designed to move plug 10 along the wellbore even when the wellbore is packed with proppant after the frac stage is completed. The alternate drive system may be incorporated on either the proximal or distal end of plug 10.

The drive system preferably has at least two drive wheels 241 and a single opposing idler wheel 242, or alternately two idler wheels 242 and a single opposing drive wheel 241. The combination of two wheels offset from the centerline on one side of plug 10 with a second opposing wheel centered on the opposite side of plug 10 creates a centralizing moment along the casing axis to keep the axis of the plug 10 centered on the axis of the well casing. Preferably, at least one drive wheel 241 is in contact with the well casing at all times while the drive system is active, even as drive wheel 241 passes over open frac ports 214 in the wall of casing segment 210.

Drive wheels 241 are preferably grooved for improved traction and have a semi-conical or tapered outer surface to fit the inside diameter of the well casing. Grooved drive wheels 241 preferably having semi-conical or semi-spherical outer surfaces are preferably fabricated from titanium alloy or other high strength steel alloy or metal matrix composite other material and coated or plated for corrosion resistance. O-rings are preferably placed in grooves on both sides of drive wheels 241 to prevent proppant and fluid intrusion into the gear cavity of drive piston 251 shown in FIG. 18.

Torque produced by drive wheels 241 preferably produces sufficient axial force to overcome resistance to motion from residual proppant buildup proximal to the repositionable plug 10 as it moves proximally from frac stage to frac stage. Furthermore, enough torque is preferably generated by motor 233 through gearbox 239 to enable plug 10 to drive up and down chamfers and other features leading into and out of port slide 211 in FIG. 19.

Drive cylinder 243 is configured to receive drive piston 251 shown in FIG. 17. Cylinder 271 holds pressure to create force to urge drive wheels 241 against the inside of the casing wall, thus enabling motion of plug 10. Drive cylinder 271 preferably has an adjacent opposing idler piston cylinder 274 to maintain plug 10 centered longitudinally in the well casing.

Accumulator 270 provides for approximately constant fluid pressure to maintain approximately constant radial force on drive wheels 241 and idler wheel 242 even as drive and idler wheels pass over imperfections in casing and variations in casing inside diameter. Accumulator 270 may use a piston opposed by one or more Belleville washers or other spring elements to provide force against piston inside accumulator 270. Alternately, accumulator 270 may be charged with nitrogen or other gas. Accumulator 270 piston preferably has one or more o-rings or other sealing elements to seal against accumulator cylinder wall to maintain pressure in accumulator 270. Hydraulic passages couple drive and idler cylinders to accumulator 270 and the input port. One or more bleed valves allow for bleeding air and gas out of the hydraulic system as needed. Preferably, coiled flexible hydraulic tube allows for disassembly of the unit for battery and component replacement without requiring the hydraulic system to be opened.

FIG. 18 shows a perspective cross-sectional view of drive piston 251 with double U-joint 259, which connects to gearbox 239, and motor 233. As shown in FIGS. 17 and 18, motor 233 transfers torque to drive wheels 241 through gearbox 239, double U-joint 259, and input shaft 258 to drive helical spur input gear 253, which drives crossed helical spur gear 261 on countershaft 255. Helical spur gear 261 is of the same handedness as input gear 253. Helical spur input gear 261 preferably drives output helical spur gear 254 of opposite handedness as input helical gear 261. Countershaft 255 provides additional mechanical offset of the input shaft from output shaft 257 to maximize the diameter of the drive wheels 241. Preferably, sleeve bearings are used on the input shaft, countershaft, and output shaft. Preferably, a brazed or welded or otherwise bonded cover 259 on drive piston 251 keeps foreign material out of the internal gear cavity in drive piston 251. Alternately, a worm gear or chain drive system or other means may be used to transfer power from the motor to the drive wheels.

A compression spring (not shown) in cylinder cavity 243 returns piston 251 to its initial retracted position inside drive cylinder 271 when force exerted on the piston 251 by pressure in the cylinder 271 decreases below the return spring compression force (see, FIGS. 17 and 18). Drive piston cylinder 271 and idler piston cylinder 274 are preferably fluidly connected to equalize pressure. Therefore, compression spring on idler piston 260 retracts idler piston 260 back into plug 10 after hydraulic pressure is reduced in idler piston cylinder to allow insertion and extraction of plug 10. Stainless steel or other o-rings on cylinder heads 272 and 273 of plug 10 provide sealing against high well pressures at high ambient well temperatures.

Driveshaft 258 prevents drive piston 251 from rotating, thus keeping drive wheels 241 aligned with the plug 10 axis. Similarly, a pin in a slot of idler piston 260 prevents idler piston 260 from rotating. Alternately, another means may be used to maintain alignment of the drive wheels 241 and idler wheel 242.

Double U-joint 259 is capable of maintaining continuous torque to the drive wheels 241 even as piston 251 moves up and down in drive cylinder 243 with variations in well casing inside diameter. Alternately chain drive or worm gear or magnetic drive or other means may be employed to drive the drive wheels 241. Alternately, drive wheels 241 are not used and two or more moveable feet may be used to reposition the well plug 10.

Use with Casing Sleeves

FIG. 19 shows a cross-sectional perspective view of a casing segment 210 with the port slide 211 in the closed position without repositionable plug 10 present. The casing segment is preferably in this closed configuration sealing the frac ports 214 when the casing string is inserted into the borehole. The casing segment as shown in FIG. 19 has threads 212 sized to mate with the well casing. The well casing is not shown in FIG. 19 or FIG. 20. A ridge 215 is preferably present on the inside diameter or other area of the port slide 211 which enables plug 10 to engage with the port slide 211 to open it. Once port slide 211 is opened, ridge 215 on port slide 211 provides structural support to hold plug 10 stationary under high pressure during the fracing process. Alternately, another type of interface feature such as one or more grooves or holes in port slide 211 may be used to secure plug 10 in port slide 211. Alternately, ridge 215 may be placed elsewhere to support the plug. Alternately, ridge 215 in sleeve is not required if, e.g., plug 10 includes casing grips to grip the well casing ID.

Preferably, one or more shear pins 218 lock port slide 211 to casing segment 210. The shear pins are preferably sized to keep the hydrodynamic forces generated due to high fluid flow rate and high density of proppant slurry during distal fracs from inadvertently opening port slide 211. Forces intentionally generated by wellhead pressure acting against the proximal surface of plug 10 act to slide port slide 211 open at the appropriate time during the well completion process. Proximal grips 14 are preferably used to capture the ridge 215 to open port slide 211 under the application of well pressure to open port slide 211 by sliding it distally. Proximal grips 14 are preferably moved into place prior to seal 9 deployment so that seal 9 can seal properly against port slide 211 inside diameter to accommodate variable port slide 211 inside diameters, out-of-round port slides 211 and slightly tapered port slides 211. Alternately, well pressure or axial force generated by plug 10 extension cylinder 32 or tractor drive may act to slide port slide 211 open. Alternately, another means may act to slide port slide 211 open. Port slide 211 and the casing segment 210 are preferably corrosion resistant, having been plated with nickel or other corrosion resistant plating or coating after machining and/or honing. O-rings 219 provide for sealing against fluid or gas leakage.

Referring to FIG. 20, the casing segment 210 is shown with port slide 211 in the open position without plug 10 present. During wellhead pressurization for fracing the current well stage, proximal grips 14 transfer force generated by pressure in the well acting against proximal end of plug 10 to ridge 215 of port slide 211 to keep plug 10 in place under the pressure of the frac, which may reach 100,000 kPa (15,000 psi) or higher.

Ports 214 in the casing wall are preferably axially elongated as shown in FIG. 19 and FIG. 20 to provide sufficient proppant and fluid flow area while being narrow enough to enable plug 10 to have at least one drive wheel 241 in contact with the casing at all times even as drive wheel 241 passes over frac ports 214 with port slide 211 open. Alternately, ports 214 may be another shape. The distal end of port slide 211 may reside in a pocket in the casing segment 210 to prevent the motion of the port slide 211 from being impaired by cement intrusion after cementing operations. A linkage or sleeve may link two or more port slides 211 together in the casing string to enable them to open together as a set if desired.

After the wellbore is drilled, the casing string is inserted into the wellbore with frac ports 214 on casing segments 210 sealed by port slide 211 in the closed position to prevent pressure loss from the well casing, enabling both cementing operations and later the fracing of distal stages of the well. If casing sleeves are employed, wireline tools may be used to check the wellbore to ensure that casing sleeves do not have excessive residual cement from cementing operations prior to fracing the well. Excessive residual cement may be removed prior to fracing with wireline tools if needed.

During the fracing of the current frac stage, plug 10 is placed into position with sealing element 9 sealing against port slide 211. Proximal grips 14 of plug 10 seat against ridge 215 of port slide 211. Upstream well pressure is applied to plug 10 which transmits force through proximal grips 14 to ridge 215 of port slide 211 to slide port slide 211 distally to open frac ports 214. The current stage is fraced, followed by a series of pressure pulses from the wellhead to signal to plug 10 to begin the sequence of actions needed to move plug 10 to the next proximally adjacent port slide 211. Alternately, an electromagnetic induction signal may be transmitted down the casing or a magnetic or ultrasonic transmitting ball may be dropped down the well, or other means may be used to transmit a signal to plug 10 to extend drive wheels 241, retract seal 9, and reposition plug 10 to the adjacent proximal port slide 211 or another location in preparation for the next frac stage.

Deployment and Retrieval Tool

FIG. 15 shows one embodiment of DR tool 150 used to insert plug 10 into the well and to position it at the proper axial location along the wellbore. This same DR tool 150 may additionally used to retrieve plug 10 from the well after the frac stages are completed. FIG. 15 shows DR tool 150 threaded onto helix 80 on the proximal end of repositionable plug 10.

The proximal end of DR tool 150 is preferably attached to a wireline or slickline as shown in FIG. 15. Hereafter, “wireline” is used to refer to “wireline or slickline.” Wireline 159 provides precise insertion positioning of plug 10, power for DR tool 150, signal transmission to and from DR tool 150 and plug 10, tethering, and a tensile element for retracting plug 10 from the well after the frac stages are completed. DR tool 150 axial position along the well is preferably controlled by wireline 159 cable length deployed down the well. Repositionable plug 10 may be retrieved after one or more frac stages and then replenished with new batteries, recharged, or replaced with another plug 10. Alternately, it may be recharged downhole. Repositionable plug 10 preferably performs multiple frac stages in the well. An induction coil on DR tool 150 can transmit data through electromagnetic signals to a coil on plug 10 configured to receive the signals.

Both DR tool 150 and plug 10 are preferably short enough in length to readily pass through a radiused section of casing in horizontal wells without becoming stuck in the casing or causing excessive friction while moving along the casing. DR tool 150 or plug 10 may optionally contain a movable joint along its length to allow it be flexible enough to pass through radii and doglegs along the wellbore.

With slight wellhead pressure caused by pump flow, DR tool 150 is run down the well casing to just proximal to the known location of the repositionable plug. The deployed wireline cable length and slight wellhead pressure control the position of DR tool 150 and plug 10 during well insertion to cause DR tool and plug 10 to be inserted to the proper well location for the most distal frac stage. During insertion, seal 9 and grips 13 and 14 are preferably retracted.

In addition to monitoring the location in the well casing through the length of wireline deployed, DR tool 150 preferably incorporates radially sensing Hall effect sensors or other sensors to detect ridges 15 in casing couplings or to detect the casing couplings itself as DR tool 150 travels along the well. Alternately, ultrasonic sensors, capacitance, or another means is used to sense ridges 15. Alternately, gamma ray detection or another method may be used to determine the precise location to release repositionable plug 10.

Preferably, DR tool 150 contains circuitry and software to acquire, process, and transmit sensor information to the operator or wireline control system at the wellbore. Through this information, potentially more accurate information on the relative distance of DR tool 150 from plug 10 may be obtained. Electrical power to DR tool 150 is preferably provided through the wireline tether 159. Alternately, batteries or other energy storage devices provide power.

Wireline 159 may be carefully controlled to exactly position plug 10 in the proper location for the first frac stage. Alternately, DR tool 150 releases plug 10 just distal to the desired location and plug 10 positions itself in proper location relative to ridge 15.

Once plug 10 is in the correct location, DR tool 150 is remotely actuated through a wireline signal transmitted through coils in DR tool 150 or through the well casing or by another means such as ultrasonic signals or pressure pulses to plug 10 to extend grips 14. Then after the appropriate time delay for grips 14 to extend, (and optionally some feedback from repositionable plug that it happened) DR tool distal head 151 rotates to release repositionable plug 10. An optional magnet on DR tool 150 conveys information picked up by plug 10 tip hall sensor that DR tool 150 auger 151 has released plug 10. After a suitable time delay for DR tool 150 to be moved distally, plug 10 moves into position adjacent to ridge 15.

If separate pyrotechnic perforation guns are deployed from the wellhead, these guns may optionally contain induction coils, pressure pulsing devices, or other means to transmit commands to plug 10 to pause its motion and seal against casing inside diameter temporarily while the pyrotechnic perforation charges are detonated. In this way, plug 10 may be protected against damage from resulting shock waves.

Preferably, plug 10 incorporates a set of perforation guns. Alternately, after DR tool 150 is removed after insertion of plug 10, separate perforating guns are sent down the wellbore to the proper location just proximal to plug 10 to create perforations in the casing. Optionally, the separate perforation guns are configured to send an electromagnetic signal or pressure signal or other signal to plug 10 that they are ready to perforate the casing. Optionally, the separate pyrotechnic perforating guns may receive a signal such as a pressure pulse, ultrasonic signal or other signal, from the repositionable plug to confirm that plug 10 is in position ready for perforation to take place. One or more pressure shock waves are likely to result from the pyrotechnic explosions creating the perforations. The seals on the repositionable plug are preferably designed to prevent fluid intrusion due to these shock waves. Alternately, other perforation techniques may be used.

Repositionable plug 10 is preferably designed to operate even when the wellbore is packed with residual proppant such as Ottawa White sand or ceramic proppant or other proppant suspended by guar or other gel after a frac stage is completed. Such residual proppant buildup is commonly found after the frac stage is completed. Because residual proppant and gelling agent will typically remain in the wellbore after the frac stage is completed, DR tool 150 is preferably designed to move through the residual proppant pack when retracting plug 10. To meet this need, one embodiment of DR tool 150 preferably features a rotating head on the distal end. DR tool 150 preferably contains a motor and gearbox or other means to drive the rotating auger 151 on DR tool 150 distal end. To ease motion through the residual proppant pack, DR tool 150 rotating auger 151 optionally has a helical strake 153 on the outer surface as shown in FIG. 22 to assist in augering through the proppant to reach and connect with plug 10 to enable retrieval. An inner helix 154 on the inside diameter of auger 151 is designed to engage onto the tip helix 80 of plug 10. Holes 155 in auger 151 allow proppant inside rotating auger 151 to be displaced outside of rotating tip. The pitch of helical strake 153 and the inside diameter helix 154 are preferably optimized based on the type of proppant, density, gelling agent, and other parameters.

Axial rotation of auger 151 about DR tool 150 axis provides engagement or disengagement with tip helix 80 of plug 10. Fins along sides of DR tool 150 body help prevent rotation of DR tool 150 due to torque reactions. Optional retractable guides or rollers on extendable members from DR tool 150 body may optionally press against the well casing ID to help center DR tool 150 and prevent rotation of DR tool 150 body and wireline 159 when torque is applied to rotate the end effector. Alternately, another design may be used.

A locking feature such as a pawl or a plug which inserts into a mating feature on the helical tip 80 of plug 10 preferably locks plug 10 to DR tool 150 to prevent plug 10 from separating from DR tool 150 during insertion or operations up or down the well.

Preferably, both DR tool 150 and plug 10 are equipped to sense the presence of each other. In one embodiment, one or more magnets or electromagnets is located in or near the rotating head of DR tool 150 to be sensed by Hall effect sensors in tip cavity 87 on plug 10 shown in FIG. 8 to sense when plug 10 helical tip 80 is fully engaged with the extraction tool, in order that plug 10 may release grips 14 and/or 13 on well casing ID. Sensor signals for position and state feedback from DR tool 150 may be sent through modem or other means up the wireline tether 159 to an operator or control system at the wellhead. This same configuration of magnets and sensors may be used to signal to DR tool 150 that DR tool 150 has separated from plug 10 after insertion to proper depth in the well.

The extraction tool may be the same tool as the insertion tool or it may be of a different design. Alternately, it may have some features that are only used for insertion and other features only used for extraction. Alternately, the insertion tool may simply consist of electromagnet using current sent down the wireline tether 159 to hold onto tip 80 of plug 10 during insertion.

Repositionable Plug Operation

The operation of repositionable multi-state plug 10 during a well frac begins after the casing has been installed with optional casing segments including the port slides. The well is cemented if required, or swellable or other packers may be used to isolate frac stages along the wellbore. The casing sleeves may remain in the well for extended periods of time prior to well stimulation. Alternately, selected stages of the well may be stimulated initially and others stimulated at a later time.

For onshore fracs, plug 10 is preferably used on set of at least two wells at a time in a “zipper frac” well stimulation operation. In the zipper frac, the casing of a first well is perforated for the impending frac stage while the stimulation of a frac stage of a second adjacent well on the same well pad takes place. In this way, the sequence of casing perforation and well fracing alternates between the two adjacent wells, optimizing equipment and crew utilization. Operation in this way is efficient because the typical duration of the fracing stimulation treatment is approximately one hour, which is approximately the time required for plug 10 to move to the new frac stage location in the adjacent zipper well, perforate the casing, move to its proper location for the frac, and expand seal 9 for the next frac stage. Optionally, the duration of the fracing treatment may vary by frac stage. Alternately, another time duration for plug movement may be used. Alternately, plug 10 may be used on a single well, or used for refracing previously fraced wells. Optionally, plug 10 is used in conjunction with coiled tubing to refrac existing wells. Alternately, plug 10 may be used in any other suitable way.

The sequence of operations for a well frac using plug 10 is as follows: Plug 10 is inserted into the well through the wellhead preferably attached to the DR Tool. As the insertion tool and plug 10 are advanced along the well by the force of gravity and positive wellhead pressure, the wireline tether constrains velocity along the wellbore. As plug 10 advances down the wellbore, the wireline monitors the plug position along the well during the insertion process. Hall effect sensors or other sensors in DR tool 150 monitor the location of the casing flanges or casing joints. Plug 10 is decelerated and distal motion of plug 10 is halted as the proximal grips 14 arrive at a position immediately proximal to the coupling flange 15 on the distal end of the most distal well stage to be fraced. Alternately, plug 10 may be positioned at any other suitable location. Distal grips 13 are extended and grip the well casing inside diameter. DR tool 150 releases plug 10 by rotation of auger 151. DR tool 150 is then withdrawn from the well.

Plug 10 then senses the casing flange 15 location or casing coupling locations through its Hall effect sensors. Alternately, plug 10 may monitor its position by tracking cylinder 32 extension cycles or by another suitable method. Plug 10 repositions itself to perforate the well casing with onboard perforation guns. After perforating the casing, plug 10 moves distally to deploy proximal grips 14 to rest on the proximal flange surface of ridge 15 (if present) to resist the frac pressure. Plug 10 then forces elastomeric seal 9 against the casing wall. Grips 14 are preferably extended into place prior to seal 9 deployment so that seal 9 can provide proper pressure to accommodate variable well casing ID variation, out of round casings, and tapered casings.

In this manner, plug 10 moves proximally along well bore from frac stage to frac stage, preferably stopping with proximal casing grips 14 just proximal to flange 15 on the casing coupling. Alternately, plug 10 stops just proximal to the coupling between casing joints. Alternately, plug 10 may stop at any other suitable location.

The most distal stage of first well 1 is then fraced by pumping proppant and water and gelling agent and other chemicals down the well at the appropriate fracing pressure(s) for the desired amount of time. Alternately, waterless fracing or another fracing technique may be used. One or more pressure signals are then sent down the well and received by the pressure sensor (strain gage) in proximal portion of plug 10 to signal to plug 10 to advance to the next frac stage.

Preferably, plug 10 is pre-programmed prior to insertion in the well with pressure vs. time profiles for frac stages and axial lengths of each frac stage. Alternately, plug 10 may respond to commands from wellhead pressure pulses or to electromagnetic signals sent down the well casing or to signals sent from a wireline tool to move the proper distance for the next frac stage. Alternately, frac stage lengths may be determined on the fly by plug 10 according to pre-programmed algorithms to analyze sensor data. Statistical methods or the assignment of sensitivity factors may be used to weight sensor readings to optimize frac stage spacing based on prior data sets. Alternately, sensor data may be transmitted from plug 10 to the wellhead for processing.

For varying frac stage lengths, plug 10 traversal distance may be controlled from the wellhead by sending a series of induction signals transmitted down the well casing or pressure pulses corresponding to a string of 1's and 0's with optional checksum for accuracy, which are sensed by coils or pressure sensors such as strain gages on the proximal portion of the plug 10. This series of pulses may be translated by the controller into a distance for plug 10 to move. Optionally, plug 10 may be sent pressure pulses from the wellbore or from optional independent perforating guns or from a wireline tool to command plug 10 to move a sufficient distance to skip a frac stage if needed.

Pressure pulses or induction signals may be used to signal the start and end of a frac stage. Pressure pulse duration and amplitude may be monitored by plug 10 and compared to preset values using an pre-programmed algorithm. Alternately, communication to and from plug 10 may be accomplished by using electromagnetic pulses induced in the casing at or near the wellhead and conducted down the casing and picked up by coils or other sensors in plug 10.

Repositionable plug 10 then begins moving to the next most proximal frac stage by extending distal grips 13 to grip the well casing inside diameter, then retracting elastomeric seal 9, and partially retracting proximal grips 14. Extension cylinder 32 then extends to its full stroke, moving the body of plug 10 proximally along the wellbore. Proximal grips 14 are then extended and exert force to grip the well tool. Distal grips 13 are then partially retracted, the extension cylinder 32 is retracted, and distal grips 13 are extended to grip the well casing ID. Proximal grips 14 are then partially retracted, then extension cylinder 32 is extended again, and the process is repeated as plug 10 moves to the next proximal frac stage. Repositionable plug 10 moves into position for the frac stage by deploying proximal grips 14 to bear against the casing to lock it in place for the frac stage, and then extends elastomeric seal 9 against the well casing ID.

Traversing the 15 m (50 foot) typical spacing between frac stages requires plug 10 to repeat the above sequence 33 times, assuming an extension cylinder 32 stroke of 46 cm (18 inches). Approximately 56 minutes is required to move plug 10 between frac stage locations, assuming 15 m (50 foot) intervals and a 46 cm (18 inch) extension cylinder stroke and 5.5 inch OD 20 lb/ft casing with 20/40 mesh Ottawa white sand used as proppant. Alternately, more or less time is required. Repositionable plug 10 can move proximally or distally along wellbore by reversing the sequence of proximal and distal grip deployments in coordination with extension cylinder movements. Once a distal stage is completed, the pressure produced by the reservoir or formation stimulated by that distal stage will help push the repositionable plug proximally to the next frac stage.

It may be desired to partially retract proximal grips 14 and distal grips 13 as plug 10 moves between frac stage in order to keep plug 10 centered on the well casing ID during motion to protect elastomeric seal 9 from casing abrasion and tearing or other damage from pyrotechnic perforation generated burrs on the casing inside diameter. Typical burrs intrude 1 mm (0.040 in) to 2 mm (0.080 in) radially into the well casing.

While repositioning plug 10, hydraulic pressure in extension cylinder 32 is preferably monitored to prevent plug 10 from becoming stuck on a casing perforation burr. If plug 10 becomes stuck, an internal algorithm can move plug 10 distally by reversing the sequence to move it proximally, followed by additional attempts to move plug 10 proximally. Alternately, as plug 10 is moving between stages, independent perforating guns are sent down the wellbore from the wellhead to the proper location proximal to the final position of plug 10 to perforate the casing by using pyrotechnic charges.

As plug 10 is moving and pyrotechnic perforations are being created for the next stage of well 1, the repositionable plug in well 2 is sealing the wellbore while the frac stage is being fraced. Once that frac stage is completed, the frac pressure is relieved at the wellhead of well 2 and applied to the wellhead of well 1 to frac its current stage while the repositionable plug in well 2 moves to the next most proximal stage in same manner as described above. The two repositionable plugs thus alternate motion in the wells, as the wells are alternately fraced in a “zipper frac” operation. Plug 10 is capable of performing as many stages per well as needed with any stage length required. Alternately, the wells may be fraced using another suitable sequence.

In addition to being useful for the fracing of new wells, the current invention simplifies the refracing of existing wells. In one embodiment of this technique, plug 10 follows the coiled tubing up the well, as successive stages are fraced to maintain frac zone isolation. The coiled tubing can send commands to plug 10 by pressure pulses, electromagnetic signals, or other means. Alternately, the present invention can also be used with sliding sleeves in the casing instead of casing perforations for both fracing and refracing operations. Alternately, the present invention can be used for stimulation of conventional reservoirs. Alternately, the present invention can be used for gravel packing of wells.

DR tool 150 preferably decelerates and moves slowly as it approaches plug 10. A bumper may be present on the distal end of the extraction tool to prevent DR tool from impacting plug 10 during downhole approaches.

Once DR Tool 150 is in proximity to plug 10, repositionable plug 10 senses electromagnetic signals or pressure pulse signals or other signals from DR tool 150. DR Tool 150 locks onto plug 10 and grips 13 and 14 are retracted in preparation for extraction from the well. With DR tool auger 151 locked to plug 10, DR tool 150 retracts plug 10 up to the wellhead.

A number of methods and compositions are discussed in the Summary of the invention and further details are provided herein and in the Examples section. As would be readily appreciated by the skilled person, the disclosures can be read in combination.

While the foregoing invention has been described in some detail for purposes of clarity and understanding, it will be clear to one skilled in the art from a reading of this disclosure that various changes in form and detail can be made without departing from the true scope of the invention. For example, all the techniques and apparatus described above can be used in various combinations. All publications, patents, patent applications, and/or other documents cited in this application are incorporated by reference in their entirety for all purposes to the same extent as if each individual publication, patent, patent application, and/or other document were individually indicated to be incorporated by reference for all purposes. 

What is claimed is:
 1. A self-retracting well casing plug system, the system comprising: a plug body comprising a proximal end and a distal end; an expandable seal mounted to the body and adapted to expand and reversibly seal the body in a well casing; one or more casing grips mounted to the body and adapted to extend from the body and engage the well casing, thereby fixing the plug at a location in the well casing.
 2. The system of claim 1, wherein the seal is resilient and comprises a fluid inlet to receive a fluid under pressure, which pressurized fluid expands the seal to contact the well case forming a hydraulic seal; or wherein the seal expands to contact the well casing on urging of an expansion device.
 3. The system of claim 1, wherein the one or more casing grips comprise grip teeth directed away from a body axis, whereby the grip teeth are adapted to grip the well casing when the grips are forced out radially from the body.
 4. The system of claim 3, wherein the grips are forced out radially by a cam and roller system in the body.
 5. The system of claim 1, wherein the well casing or a coupling between well casing segments comprise an internal ridge, and wherein the one or more grips extend to contact the ridge, thereby preventing the plug from moving past the ridge.
 6. The system of claim 1, wherein the system comprises an oil or gas well casing.
 7. The system of claim 1, further comprising a means of perforating the well casing.
 8. The system of claim 1, further comprising a well casing comprising one or more hydraulic fracturing ports and a port slide movable to alternately open or close the one or more hydraulic fracturing ports.
 9. The system of claim 1, further comprising one or more distal grips distal to the first proximal grips.
 10. The system of claim 9, further comprising one or more extension cylinders between the proximal and distal grips, whereby the distance between the proximal grips and distal grips can be increased or decreased.
 11. The system of claim 10, wherein the system is configured to reposition within the well casting by first gripping with a proximal or distal grip, increasing the distance between the proximal and distal grips, releasing the first gripping proximal or distal grip, second gripping with a grip not used in the first gripping, and reducing or increasing the distance between the proximal and distal grips by increasing or decreasing a length of the one or more extension cylinders.
 12. The system of claim 1, wherein the plug system is down hole in a well casing and untethered to the surface.
 13. The system of claim 1, further comprising a controller and one or more motors configured to actuate features selected from the group consisting of: a proximal grip, a distal grip, an expandable seal, and an extension cylinder.
 14. The system of claim 13, wherein the controller is preprogrammed or is adapted to receive communications from the surface while the plug system is down hole.
 15. The system of claim 13, wherein the controller is in communication to receive inputs from one or more sensors mounted in the plug body.
 16. The system of claim 1, further comprising a deployment and retrieval tool adapted to contact and capture the plug body.
 17. A plug system for a well casing, the plug system comprising: a plug body; an expandable seal mounted to the body and adapted to expand and reversibly seal the body in a well casing; one or more casing grips mounted to the body and extendable out from the body to engage the well casing; a source of power to extend said casing grips, whereby the plug system is movable along the well casing.
 18. The system of claim 17, wherein the seal is resilient and expands to contact the well casing on urging of a mechanical expansion device.
 20. The system of claim 17, wherein the source of power is a motor in the plug body.
 22. The system of claim 17, further comprising one or more casing grips mounted to the body and adapted to extend out from the body and engage the well casing, thereby fixing the plug at a location in the well casing.
 23. A method of plugging a well casing, the method comprising: providing a well casing plug comprising: a plug body comprising a proximal end and a distal end; an expandable seal mounted to the plug body and adapted to expand and reversibly seal the body in the well casing; a) propelling the plug body along an inside of the well casing to a first location, wherein a gripping element in contact with the well casing provides a force propelling the plug body; b) sealing the expandable seal against the well casing; c) unsealing the seal from the well casing; and d) propelling the plug to a different location within the well casing.
 24. The method of claim 23, wherein the propelling is provided by a drive wheel or by a grip/expansion cylinder combination.
 25. The method of claim 23, further comprising opening a port or perforation through the well casing between propelling steps.
 26. The method of claim 25, wherein opening a port of perforation comprises opening a port prepositioned in the well casing or opening a perforation comprises use of a pyrotechnic.
 27. The method of claim 26, further comprising pressurizing the inside of the well casing to expose an environment outside the outside of the well casing to hydraulic fracturing pressures.
 28. The method of claim 23, further comprising repeating steps b) to d).
 29. A well casing plug system comprising: a plug body; an expandable seal mounted to the body and adapted to expand and reversibly seal the body in a well casing; a digital controller in the plug body; and one or more motors configured to energize movement of well plug actuators; wherein the controller is configured to receive input from sensors or control the one or more motors.
 30. The well plug system of claim 29, wherein the seal is resilient and comprises a fluid inlet to receive a fluid under pressure, or wherein the seal is resilient and expands to contact the well casing on urging of a mechanical expansion device or annular wedge.
 31. The well plug system of claim 29, wherein the actuators are selected from the group consisting of: a proximal grip, a distal grip, the expandable seal, and an extension cylinder.
 32. The well plug system of claim 29, wherein the sensors are mounted to the plug body.
 33. The well plug system of claim 29, wherein the controller is preprogrammed or is adapted to receive communications from the surface while the well plug is down hole.
 34. The well plug system of claim 29, further comprising a deployment and retrieval tool adapted to contact and capture the plug body.
 35. The well plug system of claim 29, further comprising one or more drive wheels mounted to the body and extendable out from the body to engage the well casing and propel the body along the well casing.
 36. The well plug system of claim 29, further comprising one or more first casing grips mounted to the body and adapted to extend out from the body and engage the well casing, thereby fixing the plug at a location in the well casing.
 37. The well plug system of claim 36, further comprising one or more distal grips distal to the first proximal grips, and further comprising one or more extension cylinders between the proximal and distal grips, whereby the distance between the proximal grips and distal grips can be increased or decreased.
 38. The well plug system of claim 29, comprising the plug body and one or more perforator guns. 